Low production cost, successful gas phase can prove Åsgard investment

Complete picture beginning to emerge

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First oil from the Åsgard Fields flowed from a single well on May 19. It was a modest and late startup for a project that had been 35 months in development and attracted fierce criticism for its large cost overruns and lengthy delays.

Yet, as Statoil Chief Executive Harald Norvik put it, in many ways, the project represented a step into the unknown, and though the cost overruns are an inescapable reality, it is also a fact that the average production cost will be some 25% lower than would have been achieved in the 1980s.

Norvik, his deputy Terje Vareberg, and the Statoil board, headed by Kjell Kran, all became victims of the Åsgard furor which broke in April when it was revealed that the cost of the field development and related projects had reached NKr 64.9 billion, more than 37% above the proposed budget when the development plan was approved in 1996.

The latest estimate for the field development itself is NKr 39.8 billion, compared with an original NKr 29.7 billion:

  • The cost of the gas export pipeline has risen to NKr 8.5 billion from NKr 7.5 billion
  • The expansion of the Karst terminal, at which the gas will be treated to NKr 9.3 billion from NKr 2.8 billion
  • The Europipe II gas pipeline, through which the gas will be exported to the Continent, to NKr 7.3 billion from NKr 7 billion.

The uproar was so great that acting Oil and Energy Minister Anne Inger Lahnstein announced she was sacking the board and appointing a new one, to be headed by Ole Lund, whose various posts include the chair of the Oslo Stock Exchange. Norvik and Vareberg offered their resignations, and these were accepted by the new board, though both have been asked to stay on until replacements are found.

Without doubt, Statoil did not help its case by its tardy reporting to the Oil and Energy Ministry of the escalating costs, with the result that when the latest figures were revealed, the Storting (Norway's parliament) felt it had been kept in the dark. And this is largely taxpayers' money that is being spent, for the state has a direct interest of 46.95% in the field development, and Statoil, which is wholly state-owned, a further 13.55%.

Cost background

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ÅA came in 50% over budget, but can produce 200,000 b/d of oil, store 910,000 bbl and has a design life of 20 years.
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Even the partners have complained of not being kept fully informed. In May, Saga, backed by three other partners, Fortum, Agip, and Total, protested that NKr 1.7 billion in costs relating to the Karst expansion had been allocated to the Åsgard group, when they were the responsibility of the Statpipe group, which owns the terminal. The matter is still under discussion.

The criticisms, however, do not tell the whole Åsgard story. It is a very large, complex and technologically demanding project which, assuming that the gas production phase is successfully brought to fruition in late 2000, Statoil can justifiably claim as a great achievement.

The project involves the development of three fields, Sm rbukk, Sm rbukk South (both oil and gas fields) and Midgard, a gas and condensate field. Total reserves are of the order of 825 million bbl of oil and condensate and 212 bcm of gas, enough to justify a producing life of some 30 years currently.

The fields are in water depths with a range of 280-320 meters, for which reason it was decided to use subsea wells tied back to two floating production facilities: a pro duction ship with ample storage for the oil, and a semisubmersible platform. This represented the first application of this concept primarily for gas processing.

Challenges

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The Åsgard B gas platform's 33,000 ton deck, which has had to be built in tow halves, will be mated with the hull later this year.
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"The problem with the project has basically been technology," says Odd Mosbergvik, the Åsgard Asset Manager. "In addition, we didn't know enough about the reservoirs. The problems only became apparent after the basic plans had been laid, and we had assumed a process and technical solution. Then, we had to carry out an optimization."

The problems were exacerbated by the fact that it was a fast-track project, Mosbergvik says. This was because, in view of the competitive nature of the process for securing authorization to export gas, the licensees applied for, and were granted, authorization to start gas exports in 2000. However, the gas supply committee, FU, approved annual shipments of only 10 bcm, rather than the 12 bcm applied for, causing further modifications to the original plans.

In turn, this meant that if oil production was to be maximized, it had to begin two years earlier, in October 1998, just 28 months after approval of the plan for development and operation (PDO). This intensified the pressure on the alliance formed to build the ship, Åsgard A, which was the largest floating production, storage, and offloading (FPSO) vessel yet planned, with a production capacity of 200,000 b/d of oil and 24 MMcm/d of gas, and 910,000 bbl of oil storage.

"Another mistake we made was to take the hull with all the utility systems integrated into it to a shipyard," says Mosbergvik. "Any shipyard, no matter where we had gone, would have had problems with the detailed engineering of this scope. But this decision was taken before it was known that the construction of FPSO hulls, and FPSOs in general, was running into problems."

Construction

The hull was eventually delivered by the Hitachi Zosen yard two months late and only 60% complete. A massive effort was made at the Aker Stord yard to make up for lost time and Åsgard A was finally installed on the field in December 1998. At NKr 7.5 billion, it was however 50% over budget.

The gas platform, Åsgard B, has had similar problems. "There was no existing concept for the gas platform - it was the first time a semisubmersible had been used for gas processing," says Mosbergvik. "It was the biggest production platform of its type in the world - and that was before it became apparent, when the solution was being developed at a detailed level, that the topsides weight would have to rise from 27,000 tons to 33,000 tons." Meanwhile, the cost has risen to NKr 11.0 billion from an initial NKr 8.4 billion, most of the extra expense being assumed by Statoil.

Hull construction, however, has proceeded largely according to plan. In this case, Mosbergvik points out, the detailed design of utility systems incorporated in the hull was undertaken by the main contractor, Kværner. Construction was completed by Daewoo in South Korea in June and the structure is due to arrive at the Rosenberg yard for mating with the topsides in September.

The topsides are so massive that they are being built in two deck sections on which the modules will be installed prior to mating of the deck sections with the hull. Although one module is currently running late, the project is otherwise on schedule. The platform will have a production capacity of 38 MMcm/d of gas and 96,500 b/d of liquids, and gas injection capacity of 10.5 MMcm/d.

"For the two production facilities, we had interesting new organizational forms," Mosbergvik says. "For Åsgard A, we had an alliance which survived throughout the project. On Åsgard B, we have an integrated organization which, despite problems and strains, is also still operating."

Subsea challenges

Tough challenges also had to be faced subsea. The gas injection risers, for example, have to withstand pressures of an unprecedented 500 bar. The corrosive nature of the wellstream from the reservoirs meant that all in-field flowlines have been manufactured in 13% chrome stainless steel.

To avoid hydrate formation, the first ever direct electrical heating system has been installed on one of the flowlines, while a hot water heating system has been incorporated in the flowline bundles which tie back some of the Sm rbukk wells to Åsgard A. The cost of flowlines and risers is currently NKr 1.9 billion, up from the original NKr 1.1 billion.

Also, Statoil can claim success for the subsea production installations, the cost of which is currently NKr 7.0 billion, compared with an initial NKr 6.8 billion. "As far as subsea facilities are concerned, costs are hardly up at all," says Mosbergvik. "This is because we have been able to standardize our subsea solutions, learning through repetition over a series of projects, from Norne to Gullfaks Satellites to Åsgard." Statoil's partner for the subsea equipment is Kongsberg Offshore, which is supplying 17 standardized templates for Åsgard under a frame agreement.

Drilling hurdles

Drilling also has presented unexpected challenges. The three reservoirs are complex, but vary considerably in terms of contents, pressures, and temperatures. Well paths are mostly 5,000-8,000 meters long, mostly drilled through hard formations. Progress has been slow. The corrosive nature of the reservoir contents puts heavy demands on the durability of equipment. The prevalence of shallow gas pockets also calls for complicated safeguards.

Large additional costs have been incurred for drilling and well completion, for which total costs are now estimated at NKr 10.7 billion against the original NKr 7.5 billion. But a valuable learning process has taken place, Mosbergvik points out. "We are now averaging 110-120 meters per day, compared with 103 meters in the PDO. And completions are taking 15-20 days, compared with 40 for the first wells." Over the course of the project, the number of wells has been reduced from 59 to 54 at present, and that number could still change.

Åsgard is a product of the Norsok era, the campaign that aimed to achieve sweeping reductions in development project costs and time requirements through a combination of leading-edge technology and aligning the interests of oil company clients with their contractors and suppliers. In retrospect, Norsok's aims can be seen to have been overly ambitious, but nevertheless significant improvements can be claimed compared with previous project performance.

"With hindsight, we could have done Åsgard better," says Mosbergvik. "But even so, the project marks a significant advance, and it's been a good Norsok project." Some of the increased capital expenditure has been undertaken with a view to reducing operating costs. These are now about 20% below what was forecast in the PDO. The current breakeven price is around $14 a bbl. In Mosbergvik's estimation this breakeven price will be improved.

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A complex array of templates, flowlines, and risers link Aring;sgard's 54 wells to the two production floaters.
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"Over its lifetime we expect Åsgard to be very profitable. And with the expansion of the Karst facilities, we shall process gas from Heidrun, Norne, and Draugen, and probably undertake gas and liquid processing for Halten Bank South, with hardly any new investments."

Åsgard development profile

Fields: Smørbukk, Smørbukk South, Midgard

Location: NOR6506/11 & 12, 6507/11, 6407/2 & 3

Licensees: Statoil 60.50% (SDFI 46.95%), Agip 7.90%, Total 7.65%, Mobil 7.35%, Fortum 7.00%, Saga 7.00%, Norsk Hydro 2.60%

Reserves: Oil/condensate 825 million bbl, sales gas 212 bcm

Water depth: 280-320 meters

Production facilities:

  • Åsgard A production ship - 200,000 b/d oil, 24 MMcm gas, 910,000 bbl storage
  • Åsgard B gas platform - 38 MMcm/d gas, 90,000 b/d condensate, 6,500 b/d oil
  • Åsgard C storage unit - 868,000 bbl

Wells: Total of 54 (Smørbukk 21 producers, 12 injectors; Smørbukk South 7 producers, 3 injectors; Midgard 11 producers)

Templates: Total of 17 (Smørbukk 11, Smørbukk South 3, Midgard 3)

Flowlines: 300 km, umbilicals 110 km

Export: Liquids by offshore loading, gas by 745-km, 42-in. Åsgard Transport System pipeline to Karst

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